1. Field of the Invention
The present invention relates generally to high temperature, superheated steam generators for use in recovering crude oil of low specific gravity, the enhancement of reservoir drive, and deparrafinization. More particularly, the present invention relates to enhanced, computer controlled, high-powered superheated steam generators for producing superheated steam.
2. Description of the Related Art
It has long been recognized in the art that, when the natural drive energy of an oil reservoir or well decreases over time, natural internal pressure is inadequate to push oil to the surface. As reservoir pressure decreases over time, artificial lift will be required to achieve sufficient production. Various artificial lift processes are commonly used to increase reservoir pressure and to force oil to the surface at some time during the production life of a well.
Pumping and gas injection techniques are the two primary methods of inducing of artificial lift in wells. Beam pumping engages equipment on and below the surface to increase pressure and lift oil to the surface. Beam pumps, consisting of a sucker rod string and a sucker rod pump, are exemplified by the common “jack pumps” that are frequently employed with on-land oil wells.
Beam pumping systems rock back and forth, reciprocating a string of sucker rods, which plunge down into the wellbore. The sucker rods are connected to the sucker rod pump, which is installed as a part of the tubing string near the bottom of the well. The beam pumping system rocks back and forth to operate the rod string, sucker rod and sucker rod pump. The sucker rod pump lifts the oil from the reservoir through the well to the surface. Artificial lift pumping can also be accomplished with a downhole hydraulic pump, rather than sucker rods, or with electric submersible pump systems deployed at the bottom of the tubing string.
Artificial lift systems can employ gas injection to reestablish pressure, encouraging a well to produce. Injected gas reduces the pressure on the bottom of the well by decreasing the viscosity of the fluids, which causes fluids to flow more easily. Typically, the gas that is injected is recycled with fluids produced from the well. As the gas enters the tubing at these different stages, it forms bubbles, reduces the reservoir fluid viscosity, and lowers the pressure.
Superheated steam is ideal for gas injection. It is well known in the art to inject high temperature steam within wells to decrease the viscosity of heavy crude oils and to increase temperature, facilitating subsequent pumping and recovery. Injected steam at temperatures at or above the saturation temperature warms the well bore, heating the piping, the casings, and the surrounding environment. Injected steam must not only be of sufficient temperature and pressure to properly liquefy targeted crude oil within the well, but a sufficient volume of such steam is required during the injection process for success. Because of the relationship between temperature, volume and pressure, prior art stream generators have been limited in producing large volumes of steam because of the resultant variance in other steam parameters.
Steam generators for supplying superheated steam are known in the art. For example, U.S. Pat. No. 4,408,116 issued to Turner on Oct. 4, 1983 discloses a superheated steam generator with dual heating stages. A more recent steam generator design is illustrated in our prior pending application entitled “Super Heated Steam Generator With Slack Accommodating Heating Tanks,” filed Nov. 15, 2009, Ser. No. 12/590,919, that is owned by the same assignee as in this case, the disclosure of which is hereby incorporated by reference.
There are currently several different types of steam injection technology for oil recovery. The two primary, prior art methods are “Cyclic Steam Stimulation” and “Steam Flooding.” The “Cyclic Steam Stimulation” method, also known as the “Huff and Puff” method, consists of injection, soaking, and production stages. Steam is first injected to heat the oil in the reservoir to raise the temperature and lower the oil viscosity, thereby enhancing fluid flow. Injected steam may be left in the well for periods of time for soaking and diffusion of the steam into the well environment. Subsequently, oil is extracted from the treated well, at first by natural flow (since the steam injection will have increased the reservoir pressure) and then by artificial lift. Production decreases as the oil/steam mixture cools, necessitating repetition of the steam injection steps. The “huff and puff” method thus injects steam in periodic cycles, applying periodic “puffs” of steam between periodic soaking periods, during which the steam generator apparatus recharges and accumulates another volume of steam for subsequent injection. The “huff and puff” process is most effective in the first few steam cycles. However, it is typically only able to recover approximately twenty-percent of the Original Oil in Place (OOIP), compared to steam flooding, which has been reported to recover over fifty-percent of OOIP.
Steam flooding usually involves multiple wells. Oil production wells are complimented by separate steam injection wells. Two mechanisms are at work to improve the amount of oil recovered. The first is to heat the oil to higher temperatures and to thereby decrease its viscosity so that it flows more easily through the formation toward the producing wells. A second mechanism is the physical displacement occurring in a manner similar to water flooding, in which oil is pushed to the production wells. While more steam is needed for this method than for cyclic steam simulation methods, it is typically more effective at recovering a larger portion of the oil.
One form of steam flooding termed “steam assisted gravity drainage”, abbreviated “SAGD,” utilizes multiple, spaced apart, horizontal wells. Steam is injected into an upper SAGD well in an effort to reduce the viscosity of the oil deposits to the point where gravity will pull the oil into the producing well.
However, it has become evident to us that, for maximum crude oil recovery efficiency, superheated steam can be injected concurrently with an extraction operation in a single well. In this manner, time delays are avoided, and additional energy is available through the large number of degrees of superheat (defined as the difference between the actual steam temperature and the saturation temperature at the delivery pressure). The requirement of supplemental wells is obviated.
A variety of steam generators and associated steam injection techniques have been proposed. A recognized difficulty in the art relates to the generation of superheated steam at proper temperatures, pressures, and volumes. Injected steam must not only be of sufficient temperature to properly liquefy targeted crude oil within the well, but a sufficient volume of such steam is required during the injection process for success.
Previously it has been known in the art to provide a steam heater with an internal tank positioned coaxially within an outer shroud. It is known to use electric heating elements surrounded by lead disposed between a peripheral enclosure and an internal evaporator tank. As the lead heats and melts from the heating elements, heat is transferred by conduction. Molten metal (i.e., lead) surrounding each evaporator tank transfers heat to it by conduction. This basic construction is shown in Mexican patent No. 97201, issued November 1968. However, with the latter device, steam output temperatures vary widely, and critical operating parameters including tank and water temperature, output pressure and output volume are not dynamically controlled. Liquid levels within various tanks can vary constantly, resulting in irregular vaporization. Temperature fluctuations of between 400° and 600° F. were experienced, compromising operating the efficiency of the steam generation system. Steam generators with multiple stages for enhancing crude oil recovery are known in the art. For example, U.S. Pat. No. 4,408,116 issued to Turner on Oct. 4, 1983 discloses a superheated steam generator with dual heating stages. The latter design employs a plurality of radially spaced-apart first stage heaters that surround a central second stage heater. Water is supplied to each of the first stage heaters via interior feed tubes. A rigid, tubular sheath coaxially surrounds and protects each of the last mentioned tubes, and defines a steam output annulus between the sheath and the mouth of each first stage tank. Steam from the first stage tanks or pressure vessels is transmitted to the second stage pressure vessel by a plurality of conduits extending from first stage to a central manifold feeding an encircled second stage tank. Again, heat transfer between the heating elements and the evaporator tanks is primarily effectuated by conduction. Experiments have continued over the years with apparatus constructed in accordance with prior U.S. Pat. No. 4,408,116 mentioned above. As the price of crude oil increases, more and more efforts have been undertaken to recover deposits from marginal domestic wells. However, one common weakness in prior devices has been the inability to reliably and virtually continuously generate and deliver a large volume of high temperature, superheated steam. One problem has been experienced with the electrodes used to heat internal vaporization or evaporation tanks, and with other critical components. Wide temperature variations are encountered in use. Prior to energization, for example, the component temperature is that of the environment, i.e., ambient temperature. After heating commences, a temperature rise in excess of 1000° F. occurs. Because of the resultant thermal expansion of the metal components, and the various different coefficients of expansion that characterize parts of different construction materials, extreme stresses occur, as the dimensions of critical parts expand during heat-up. Most disturbingly, failures associated with such mechanisms as creep and creep fatigue occur over time in threaded pipe fittings employed with steam machines of the type described in the latter patent.
The stress problem has caused component failure in the past, necessitating time consuming and expensive field repairs. For example, because of the traditional mounting techniques used for high temperature tanks that are bathed within liquid lead during operation, component failures have been frequent. One recurrent problem, for example, has been burn-out or failure of critical electrical heating elements disposed within each heater assembly. These problems have been aggravated by the prior art use of liquid lead as a heat distribution medium or thermal mass. The configuration of internal parts such as the electrode heater elements, and the lack of precision, militate against proper dynamic control of operating points necessitated by manual operation.
In our prior pending U.S. application entitled “Super Heated Steam Generator With Slack Accommodating Heating Tanks,” filed Nov. 15, 2009, Ser. No. 12/590,919, which is owned by the same assignee as in this case, a partial solution was proposed. For example, new electrode configurations, combined with a flexible tank mounting arrangement that accommodates thermal expansion and component shifting was proposed. After substantial field tests of the apparatus described in the aforementioned application, it has been concluded that the use of liquid lead for heat transfer is a fundamental problem. Moreover, reliance upon thermal conduction as a heat transfer mechanism appears to be a flawed approach, when compared to the other methods of heat transfer that may be available, such as convention and radiation heat transfer modes.
For example, when service is required to repair an internal component such as an electrode, the entire unit must first be allowed to cool to a temperature safe for repairs. When the unit is later opened for service, the technician encounters irregularly shaped formations of solid lead. Critical parts that must be removed are often partially captivated in the solid, unwieldy mass of cooled lead. Even worse, when component failure or breakage leads to a crack or the formation of pin holes, molten lead may leak from the tanks or pressure vessels. The repair technician is thus faced with a time consuming job requiring substantial lead clean-up. Solid lead waste is tedious to remove, requiring blow torches and the liberal use of protective gear and clothing. The environmentally proper disposal of lead waste is difficult as well.
Accordingly, it is suggested that inner pressure vessels within heating vessels should not be heated primarily by conduction phenomena, but rather by radiation. Heating elements must be arranged proximate the pressure vessels to provide adequate heat via radiation heat transfer, without overheating or burnout.
Thus, with a radiant heating design, to reach operating temperatures approximating 1200° F., the water and steam injection pathways must be dynamically controlled. While various prior art steam injection heaters have utilized piping arrangements establishing fluid flow in heat exchange relation, an adequate high temperature, superheated steam injection system must employ water control apparatus that minimized fluid-blocking back-pressures that are characteristic of prior art designs. Most importantly, it has been found that fluid flow paths must be continuously monitored and dynamically varied in response to sensed operating parameters. Temperatures within each pressure vessel must be continuously controlled. Thus, for example, water flow can be computer-sensed and computer-controlled to moderate operating temperatures while achieving proper output volumes. Simple, manually operated valves in water control pathways, for example, are insufficient as they are unable to respond in real time to dynamic operating conditions. Means must be provided for monitoring temperatures associated with the pressure vessels at judiciously spaced locations within the modules, and to respond to varying temperature gradients within the steam system. Water flow and electrode heater power must be coordinated with observed temperatures and pressures.
Further, dynamic operating parameters must be varied according to differing conditions experienced during different stages of operation. Recognizable phases of steam generator operation can be broadly classified into “start-up,” “ramp-up,” “steady state” and “shut down” phases, each of which requires different operational parameters. In other words, it has been determined that optimal operating conditions vary depending upon the stage of operation, and parameter correction is required. Thus a computer-controlled, dynamically monitored system is necessary for optimizing critical operational parameters during enhanced, super-heated steam generator operation.